In the drilling of oil and gas wells, a wellbore is formed using a drill bit that is urged downwardly at a lower end of a drill string. After drilling to a predetermined depth, the drill string and bit are removed and the wellbore is lined with a string of casing. An annular area is thus formed between the string of casing and the formation.
A cementing operation is typically conducted in order to fill or “squeeze” the annular area with cement. This serves to form a cement sheath. The combination of cement and casing strengthens the wellbore and facilitates the isolation of the formations behind the casing.
It is common to place several strings of casing having progressively smaller outer diameters into the wellbore. Thus, the process of drilling and then cementing progressively smaller strings of casing is repeated several or even multiple times until the well has reached total depth. The final string of casing, referred to as a production casing, is cemented into place. In some instances, the final string of casing is a liner, that is, a string of casing that is not tied back to the surface, but is hung from the lower end of the preceding string of casing.
In some instances, a well may be completed as an open-hole completion. This means that the final tubular body run into the wellbore is not cemented into place; instead, a perforated liner may be installed. Where the producing formation is located in a sandstone or other loose or unconsolidated formation, a sand screen may alternatively be used. A production string or “tubing” is then positioned inside the wellbore extending down to the last string of casing.
There are certain advantages to open-hole completions versus cased hole completions. First, because open-hole completions have no perforation tunnels, formation fluids can converge on the wellbore radially 360 degrees. This has the benefit of eliminating the additional pressure drop associated with converging radial flow and then linear flow through particle-filled perforation tunnels. The reduced pressure drop associated with an open-hole completion virtually guarantees that it will be more productive than an unstimulated, cased hole in the same formation.
Second, open-hole completions, including gravel pack techniques, are oftentimes less expensive than cased hole completions. For example, the use of perforated liners and gravel packs eliminates the need for cementing, perforating, and post-perforation clean-up operations.
As an additional step in the wellbore completion process, production equipment such as tubing, packers and pumps may be installed within the wellbore. A wellhead (or “tree”) is installed at the surface along with fluid gathering and processing equipment. Production operations may then commence.
Before beginning production, it is sometimes desirable for the drilling company to “stimulate” the formation by injecting an acid solution through the casing. This is particularly true when the formation comprises carbonate rock. In operation, the drilling company injects a concentrated formic acid or other acidic composition into the wellbore, and directs the fluid along and even into the near-wellbore region. This is known as acidizing. The acid helps to dissolve carbonate material, thereby opening up porous channels through which hydrocarbon fluids may flow into the wellbore. In addition, the acid helps to dissolve drilling mud that may have invaded the formation. Acid stimulation as described above is a routine part of petroleum industry operations.
In many wellbores, it is now common to complete a well through multiple zones of interest. Such zones may represent up to about 30 meters (100 feet) of gross, vertical thickness of subterranean formation. When there are multiple or layered reservoirs to be hydraulically fractured, or a very thick hydrocarbon-bearing formation, then more complex treatment techniques may be required to obtain treatment of the entire target zone. In this respect, the drilling company must isolate various zones to ensure that each separate zone is adequately treated. In this way the operator is sure that stimulation fluid is being injected into each zone of interest or along the entire zone of interest to effectively increase the flow capacity at each desired depth.
To do this, various fluid diversion techniques may be employed. Two general categories of fluid diversion have been developed to help ensure that the acid reaches the desired rock matrix—mechanical and chemical. Mechanical diversion involves the use of a physical or mechanical diverter that is placed within the wellbore. Chemical diversion, on the other hand, involves the injection of a fluid or particles along and into the formation itself.
Referring first to chemical diverters, chemical diverters include foams, particulates, gels, and viscosified fluids. Foam commonly comprises a dispersion of gas and liquid wherein a gas is in a non-continuous phase and liquid is in a continuous phase. Where acid is used as the liquid phase, the mixture is referred to as a foamed acid. In either event, as the foam mixture is pumped downhole and into the porous medium that comprises the original, more permeable formation, additional foam is generated. The foam initially builds up in the areas of high permeability until it provides enough resistance to force the acid into the new zone of interest having a lower permeability. The acid is then able to open up pores and channels in the new formation.
Particulate diverters consist of fine particles. Examples of known particulate diverters are cellophane flakes, oyster shells, crushed limestone, gilsonite, oil-soluble naphthalenes, and even chicken feed. Within the last several years, solid organic acids such as lactic acid flakes have been used. As the particles are injected, they form a low permeability filter-cake on the face of wormholes and other areas of high permeability in the original formation. This then forces acid treatment to enter the new zone(s) of interest. After the acidizing treatment is completed, the particulates hydrolyze in the presence of water and are converted into acid.
Viscous diverters are highly viscous materials, sometimes referred to as gels. Gels use either a polymer or a viscoelastic surfactant (VES) to provide the needed viscosity. Polymer-based diverters crosslink to form a viscous network upon reaction with the formation. The crosslink breaks upon continued reaction and/or with an internal breaker. VES-based diverters increase viscosity by a change in micelle structure upon reaction with the formation. As the high-viscosity material is injected into the formation, it fills existing wormholes. This allows acid to be injected into areas of lower permeability higher in the wellbore. The viscosity of the gel breaks upon exposure to hydrocarbons (on flowback) or upon contact with a solvent.
Chemical diverters may have limited effectiveness in certain situations. For example, if the density of the acid and the diverting fluid is considerably different, or if the wellbore significantly deviates from vertical, the interface of the acid with the diverter may break down or experience distortion while traveling down the wellbore. In some cases, this distortion may involve the mixing of acid and an acid-containing diverter. This, in turn, reduces the viscosity of the diverter, thereby reducing the diverter effectiveness and the overall performance of the stimulation job. Depending on stage size, fluid density, fluid viscosity, and pumping rate, the interface distortion may be severe.
Referring now to mechanical diverters, various types of mechanical diverters have been employed. These generally include ball sealers, plugs, and straddle packers. For example, U.S. Pat. No. 3,289,762 uses a ball that seats in a baffle to cause mechanical isolation. U.S. Pat. No. 5,398,763 uses a wireline to set and then to retrieve a baffle. The baffle isolates a portion of a formation for the injection of fluids. U.S. Pat. No. 6,491,116 provides a fracturing plug, or “frac plug.” Frac plugs are common in the industry and rely upon a ball that is either dropped from the surface to land on a seat, or that is integral to the plug itself. Frac plugs generally require a wireline for setting. Frac plugs may also be retrieved via wireline, although in some instances frac plugs have been fabricated from materials that can be drilled out. Drilling out the material adds time and expense to the stimulation operation.
Mechanical plugs are used to isolate an interval after successfully stimulating each zone. Although the stimulation of each zone separately can be very effective, multiple electric line runs and acid stimulations may be required to fully stimulate a long interval, increasing the time and cost of the acid treatment. Further, while mechanical plugs can provide high confidence that formation treatment fluid is being diverted, there is a risk of incurring high costs due to mechanical and operational complexity of the plugs. Plugs may become stuck in the casing resulting in a lengthy and costly fishing operation. If unsuccessful, a drill rig may be needed to be brought on-sight to drill the plug out. Drilling out the plug is not preferred due to the time and cost associated with mobilizing a drill rig on location. In some situations, the well may have to be sidetracked or even abandoned. Mechanical plugs particularly have a history of reliability issues in large diameter wells. In this respect, it can be difficult to locate a plug suitable for a large borehole, and those that are available have a history of failures.
A need therefore exists for an acid diverting system and method that offers the reliability of a mechanical plug without the risk of mechanical failure or sticking. Further, a need exists for a system that optimizes the acid circulation process by removing the need for a wireline, and yet has greater reliability than a viscous chemical diverter. A need further exists for a system that improves the stimulation of a formation along the entire length of a deviated, open-hole wellbore.